Natural gas is an important fuel gas and it is used extensively as a basic raw material in the petrochemical and other chemical process industries. The composition of natural gas varies widely from field to field. Many natural gas reservoirs contain relatively low percentages of hydrocarbons (less than 40%, for example) and high percentages of acid gases, principally carbon dioxide, but also hydrogen sulfide, carbonyl sulfide, carbon disulfide and various mercaptans. Removal of acid gases from natural gas produced in remote locations is desirable to provide conditioned or sweet, dry natural gas either for delivery to a pipeline, natural gas liquids recovery, helium recovery, conversion to liquefied natural gas (LNG), or for subsequent nitrogen rejection. H2S is removed because it is toxic in minute amounts and it is corrosive in the presence of water through the formation of hydrosulfurous acid. Upon combustion, H2S forms sulfur dioxide, a toxic and corrosive compound. CO2 is also corrosive in the presence of water, and it can form dry ice, hydrates and can cause freeze-up problems in pipelines and in cryogenic equipment often used in processing natural gas. Also, by not contributing to the heating value, CO2 merely adds to the cost of gas transmission.
An important aspect of any natural gas treating process is economics. Natural gas is typically treated in high volumes, making even slight differences in capital and operating costs of the treating unit significant factors in the selection of process technology. Some natural gas resources are now uneconomical to produce because of processing costs. There is a continuing need for improved natural gas treating processes that have high reliability and represent simplicity of operation.
A number of processes for the recovery or removal of carbon dioxide from gas steams have been proposed and practiced on a commercial scale. The processes vary widely, but generally involve some form of solvent absorption, adsorption on a porous adsorbent, distillation, or diffusion through a semipermeable membrane.
Membranes are thin barriers that allow preferential passage of certain components of a multi-component gas mixture. Most membranes can be separated into two types; porous and nonporous. Porous membranes separate gases based on molecular size and/or differential adsorption by small pores in the membrane. Gas separation membranes used in natural gas applications are often nonporous or asymmetric and separate gases based on solubility and diffusivity. These membranes typically have a microporous layer, one side of which is covered with a thin, nonporous “skin” or surface layer. The separation of the gas mixtures through an asymmetric membrane occurs in its skin, while the microporous substrate gives the membrane mechanical strength.
In a typical membrane separation process, a gas is introduced into the feed side of a module that is separated into two compartments by the permeable membrane. The gas stream flows along the surface of to membrane and the more permeable components of the gas pass through the membrane barrier at a higher rate than those components of lower permeability. After contacting the membrane, the depleted feed gas residue stream, retentate, is removed from contact with the membrane by a suitable outlet on the feed compartment side of the module. The gas on the other side of the membrane, the permeate, is removed from contact with the membranes the permeate side, through a separate outlet. The permeate stream from the membrane may be referred to as being “enriched” in the readily permeable components relative to the concentration of the readily permeable components in the retentate stream. The retentate may also be referred to as being “depleted” of the readily permeable components. While the permeate stream can represent the desired product, in most natural gas permeation processes the desired product is the retentate stream, and the permeate stream comprises contaminants such as CO2 or other acid gases.
The efficiency of a membrane depends on many factors including the pressure differential being maintained across the membrane, whereby the permeable fluid component(s) permeate to the permeate side of the membrane under a partial pressure gradient. In order to maintain the partial pressure differential across the membrane, a sweep fluid is often used to help remove the permeating fluid. The lower the partial pressure of the permeate, the better the separation. This is especially important in applications where only small amounts of fluid are to be separated from the fluid mixture. However, many uses for the permeate require further pressurization of the permeate. Low permeate partial pressure is desired for efficient membrane application, but high permeate pressure is desired to reduce compression costs.
While membrane systems that use sweep fluids have been effective in improving the efficiency of membrane separation of fluid, there is a continuing need for improving to efficiency of membrane separation processes.